Simplistically, microseismic monitoring, in the context of the oil and gas industry, typically requires placement of receiver systems at surface or otherwise adjacent a microseism or downhole event, such as in an adjacent wellbore, for detecting and locating the events in time and space. The microseisms occur either as a result of a process occurring within a wellbore such as drilling, or pumping fluids, or as a result of events adjacent the wellbore, such as the creation and propagation of hydraulically-induced fractures in the surrounding formation. Further, the microseisms can be purposefully initiated in the wellbore or near wellbore such as by firing a string shot or a perforating shot therein to obtain data. Such data can instruct as to velocity within the various strata of the formation surrounding the wellbore, to better understand the nature and extent of the zones of interest therein.
The receiver systems, typically geophones or accelerometers which can be single component or three-component, receive compressional (P-wave) and shear (S-wave) data generated from the microseism and the data are used to locate and map the events at least in space, typically using Cartesian co-ordinates, X, Y and Z.
Typically, a 3-D seismic velocity model is created using the microseismic data from a zone of interest. Measured or estimated microseismic data typically comprises a time of occurrence of a microseismic event within the zone, a location of occurrence of the microseismic event within the zone, and an arrival time of the time and location data at a detection point, typically at a surface array. Prior art microseismic monitoring typically relies on geological information via downhole logs to determine the velocity of microseismic events downhole with varying degrees of accuracy. In many cases, estimated values for at least some of the parameters required to create the velocity profile must be made, as accurate measurements and synchronized time-stamping of the microseismic event in the zone of interest have been difficult to measure directly using conventional technologies.
The velocity model is typically used to calculate the position of microseismic events and monitor the growth or propagation of a fracture or to understand the geometry of the developing fracture within the zone. It is assumed that the microseismic events are generated by the fracture in the formation. This information can be used to optimize the fracture by controlling its growth and extent and thereby improve oil and gas production. In order to ensure the velocity model is accurate, the microseismic data collected must be accurate. Accuracy of the microseismic data collected depends on the accuracy of the time data, location data for the surface probes and arrival times of the event at the surface probes. As microseismic amplitudes are small, detection of the event at surface may be difficult.
In many prior art systems the velocity model is created using as least some estimated or calculated parameters. Thereafter, the velocity model is used together with measured time data to calculate the position of the microseism in 3D space. Inaccuracies in the velocity model result in incorrect mapping of the event. The inaccuracies, when relying upon the map for placement of fractures within very restricted zones of interest, may result in fractures which are not positioned properly relative to the wellbore (azimuthal errors) and do not extend to the furthest extents of the zone resulting in reduced or less than optimal production. Further, the inaccuracies may result in fractures that exceed the zone of interest and result in break through, formation damage in sensitive zones and other adverse effects.
Typically, systems which monitor microseismic events and propagation of the fracture using sensors located in an offset, vertical wellbore, are more accurate in positioning the event vertically in space (Z) and are less accurate when determining horizontal co-ordinates (X,Y). Conversely, systems which measure the event at surface, such as using an array of surface sensors, are typically more accurate in positioning the event along the horizontal axes (X,Y), but are less accurate in measuring the vertical location (Z). Detection may be adversely affected by the formation characteristics resulting in poor signals particularly in the case of microseismic events which are typically relatively small.
Others have attempted to improve microseismic monitoring by utilizing optical fibers to replace conventional sensors for measuring microseisms and, in particular, for real-time monitoring of hydraulic fracturing.
As described in SPE Paper 152981; “Real-Time Downhole Monitoring of Hydraulic Fracturing Treatments Using Fiber Optic Distributed Temperature and Acoustic Sensing”; Molenaar et al, March 2012, in 2009 it was demonstrated that fiber optic distributed sensing could be used for downhole applications. It has been shown that optical fiber deployed into a wellbore, permanently or temporarily, can be used to measure temperature, strain, pressure and acoustics. It has been proposed that the combination of fiber optic distributed sensing of temperature (DTS) in combination with fiber optic distributed acoustic sensing (DAS) may permit real-time monitoring to understand the complexity of the fracturing treatments.
As one of skill will appreciate, distributed sensing utilizes the light scatter which occurs in an optical fiber. When using fiber optics having sensors based on Raleigh scattering, the light scattered back from the fiber has three different spectral parts which are detected and analyzed for measuring the various parameters:                the Raleigh scattering with the wavelength of the laser source used;        the Stokes line components from photons shifted to longer wavelength (lower frequency);        the anti-Stokes line components with photons shifted to shorter wavelength (higher frequency) than the Raleigh scattering.        
As one of skill in the art will appreciate different types of fibre optics may have different types of sensors, such as Bragg gratings, the light scattered therefrom being analyzed for parameters appropriate thereto.
In the case of distributed acoustic sensing, a standard single-mode optical fiber acts as an array of microphones which provide acoustic data detected within the vicinity of the fiber. For example, a 5 km long fiber can be interrogated using DAS so that every 5 m can be recorded providing 1,000 independent, simultaneously sampled acoustic sensors, each with a 20 kHz bandwith. Parameters can be adjusted to optimize performance.
A short pulse of coherent light is sent down the fiber and the backscattered light is detected on a photo detector (at surface). The backscattered light is processed to extract the acoustic signals from each position along the fiber. Pressure pulses, such as observed with seating of balls in “plug and pert” operations, are also detected by DAS.
In testing, described in SPE Paper 152981, the fiber-optic cable was attached along an outside of production casing. Where the wellbore was cased and cemented, the fiber-optic cable was attached to the outside of the casing and was thereafter embedded in the cement.
As taught in US 2011/0292763 to Coates et al (Schlumberger Technology Corporation) optical fiber cable has been attached to the inside or the outside of tubing, including coiled tubing, casing and the like, in a variety of ways such as magnetically, using adhesive or cementing the fiber in place. The fiber optic sensors are either bare or encased along their length in a protective coating or jacket. Further, the sensors may be encased in a compliant material that is particularly sensitive to pressure, such as metalized foam or an acoustic-matching medium, typically a gel, for enhancing sensitivity of the seismic measurement. The fiber optic cable can also be installed inside a control line or other thin-walled tubing.
One or more of the fiber optic distributed sensors are deployed into one or more boreholes. The fiber is disturbed by the passing seismic waves and is strained by the waves if the waves couple to the fiber. A strain on the fiber changes the relative position between the scattering centers by simple elongation of the fiber. The strain also changes the refractive index of the glass of the fiber. Both of these effects alter the relative phase of the light scattered from each scattering center as is understood by those of skill in the art. The electrical signals emerging from a detector at surface are processed to detect the passage of a seismic wave and possible to determine the relative time of the wave's passage at different locations along the borehole and possibly the wave's spectral content.
Clearly, there is interest in the industry for apparatus and methods which effectively and efficiently detect and monitor microseismic events. Further, there is interest to improve the quality of the data obtained for deriving information regarding the microseismic events occurring beyond the wellbore and for reducing noise associated with events other than those of interest.